System and method for managing use of a downhole asset

ABSTRACT

A system and method for managing use of a downhole asset. In one embodiment, a system includes a rig interface, a tag reader, and FIG.  1  a remote datacenter. The rig interface is disposed proximate to a borehole being drilled, and configured to process information related to use and physical condition of the downhole asset while drilling the borehole. The tag reader is configured to transfer a measurement of an attribute of the downhole asset to the rig interface. The remote datacenter is disposed remote from the borehole and is configured to assess the condition of the downhole asset based on information received from the rig interface and additional information related to use of the downhole asset received by the remote datacenter over the life of the downhole asset.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a 35 U.S.C. §371 national stage application ofPCT/US11/34177 filed Apr. 27, 2011, which claims the benefit of USprovisional application 61/328,374 filed Apr. 27, 2010, both of whichare incorporated herein by reference in their entirety for all purposes.

BACKGROUND

Modern oil field operations demand a great quantity of informationrelating to the parameters and conditions encountered downhole. Suchinformation typically includes borehole environmental information, suchas temperature, pressure, etc., and drill string operational information(e.g., stresses encountered by drill string components).

Various methods for acquiring downhole information have been used. Forexample, measurement instruments may be introduced into the borehole bywireline after extraction of the drill string. Alternatively, the drillstring may include measurement tools that transmit downhole informationto a surface facility via media incorporated in the drill string ordrilling fluid pressure modulation.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of exemplary embodiments of the invention,reference will now be made to the accompanying drawings in which:

FIG. 1 shows a drilling system including downhole tags in accordancewith various embodiments;

FIG. 2 shows a drilling system including downhole tags and a downholetag interrogating device in accordance with various embodiments;

FIG. 3 shows a cross-section of drill pipe including a downhole tagcommunicating with a downhole tag interrogating device in accordancewith various embodiments;

FIG. 4 shows a block diagram of a downhole tag in accordance withvarious embodiments;

FIG. 5 shows a block diagram of a downhole tag interrogating device inaccordance with various embodiments;

FIG. 6 shows downhole tag packaging in accordance with variousembodiments;

FIG. 7 shows downhole tag packaging in accordance with variousembodiments;

FIG. 8 shows a representation of sensor measurements indicationsrecorded by a downhole tag in accordance with various embodiments;

FIG. 9A shows an adapter for attaching a downhole tag to a wellboretubular in accordance with various embodiments;

FIG. 9B shows an adapter for attaching a downhole tag to a wellboretubular in accordance with various embodiments;

FIG. 10 shows a flow diagram for a method for retrieving informationfrom a downhole tag in accordance with various embodiments;

FIG. 11 shows a flow diagram for a method for storing information in adownhole tag in accordance with various embodiments;

FIG. 12 shows a system for acquiring information related to downholeasset in accordance with various embodiments;

FIG. 13 shows a block diagram of a system for processing informationrelated to a downhole asset in accordance with various embodiments;

FIG. 14 shows a flow diagram for a method for processing informationrelated to a downhole asset in accordance with various embodiments;

FIG. 15 shows a display of information related to a downhole assetincorporated in a drill string in accordance with various embodiments;

FIG. 16 shows a display of use information for a downhole asset inaccordance with various embodiments; and

FIG. 17A shows a side view of a downhole tool including a threadprotector that measures tool use time in accordance with variousembodiments;

FIG. 17B shows a perspective view of the downhole tool and threadprotector of FIG. 17A; and

FIG. 17C shows a perspective cross-sectional view of the downhole tooland thread protector of FIG. 17A.

NOTATION AND NOMENCLATURE

Certain terms are used throughout the following description and claimsto refer to particular system components. As one skilled in the art willappreciate, companies may refer to the same component by differentnames. This document does not intend to distinguish between componentsthat differ in name but not function. In the following discussion and inthe claims, the terms “including” and “comprising” are used in anopen-ended fashion, and thus should be interpreted to mean “including,but not limited to . . . .” Also, the term “couple” or “couples” isintended to mean either an indirect, direct, optical or wirelesselectrical connection. Thus, if a first device couples to a seconddevice, that connection may be through a direct electrical connection,through an indirect electrical connection via other devices andconnections, through an optical electrical connection, or through awireless electrical connection. Further, the term “software” includesany executable code capable of running on a processor, regardless of themedia used to store the software. Thus, code stored in memory (e.g.,non-volatile memory), and sometimes referred to as “embedded firmware,”is included within the definition of software.

DETAILED DESCRIPTION

The following discussion is directed to various embodiments of theinvention. Although one or more of these embodiments may be preferred,the embodiments disclosed should not be interpreted, or otherwise used,as limiting the scope of the disclosure, including the claims. Inaddition, one skilled in the art will understand that the followingdescription has broad application, and the discussion of any embodimentis meant only to be exemplary of that embodiment, and not intended tointimate that the scope of the disclosure, including the claims, islimited to that embodiment.

Acquisition of borehole information can entail significant expenserelated to, for example, incorporating measurement tools and telemetrysystems in the drill string. Embodiments of the present disclosureinclude downhole tags affixed to drill string components or otherwellbore tubulars to provide an effective and less costly means ofmeasuring wellbore parameters. The downhole tags measure and recorddownhole information and/or operational information associated with acomponent incorporating the tag. A tag interrogating device may bepassed though the interior of the drill string to extract informationrecorded by the downhole tags and transfer the extracted information toa surface facility for analysis. Various embodiments of the downhole tagmay store measurements as a function of time and/oroccurrence-frequency.

FIG. 1 shows a drilling system including downhole tags 26 in accordancewith various embodiments. A drilling platform 2 supports a derrick 4having a traveling block 6 for raising and lowering a drill string 8. Akelly 10 supports the drill string 8 as it is lowered through a rotarytable 12. A drill bit 14 is driven by a downhole motor and/or rotationof the drill string 8. As bit 14 rotates, it creates a borehole 16 thatpasses through various subsurface formations. A pump 20 circulatesdrilling fluid through a feed pipe 22 to kelly 10, downhole through theinterior of drill string 8, through orifices in drill bit 14, back tothe surface via the annulus around drill string 8, and into a drillingfluid reservoir 24, such as a mud tank or retention pit. The drillingfluid transports cuttings from the borehole into the reservoir 24 andaids in maintaining the borehole integrity.

The drill string 8 is made up of various components, including drillpipe 18 and bottom hole assembly components (e.g., bit 14, mud motor,drill collar, tools, etc.). In embodiments of the present disclosure,some drill string components, for example drill pipe 18, include adownhole tag 26 that measures and records borehole environmentalparameters and/or drill string component operational parameters.

FIG. 2 shows a drilling system including downhole tags 26 and a downholetag interrogating device 28 in accordance with various embodiments. Insome embodiments, the downhole tag interrogating device (i.e., the tagreader) 28 is inserted into the interior of the drill string 8. A cable42, that may include power and/or data conductors for providing power tothe tag reader 28 and telemetry between the tag reader 28 and a surfacefacility 44, allows the tag reader 28 to be lowered through the drillstring 8 and returned to the surface. As the tag reader 28 moves into apredetermined proximity of the tag 26 (e.g., within wirelesscommunication range), the tag reader 28 detects the presence of the tag26, establishes a wireless communication session with the tag 26, andretrieves information collected and stored by the tag 26. Retrievedinformation may include temperature, pressure, acceleration, and/orother wellbore environmental information.

In some embodiments, the tag reader 28 internally stores informationextracted from the tags 26, and the information is provided to thesurface facility 44 after the tag reader 28 is withdrawn from the drillstring 8. In some embodiments, the tag reader transmits informationretrieved from the tags 26 to the surface facility 44 via the cable 42.

Some embodiments of the drilling system include a tag reader 28 locatedon the drilling platform 2 to retrieve information collected by the tag26 as the drill string 8 is moved into or out of the borehole 16. Insome embodiments, the tag reader 28 is a handheld device.

In some embodiments, the surface facility 44 is local to the drillingplatform 2 as shown in FIG. 2. In other embodiments, the surfacefacility 44 may be a server or other computing device located remotelyfrom the drilling platform 2. In such embodiments, information retrievedfrom a downhole tag 26 may be transferred to the surface facility 44 viaa network (e.g., the Internet, a private wide area network, etc.) forstorage and analysis.

FIG. 3 shows a cross-section of drill pipe 18 including a downhole tag26 communicating with a downhole tag interrogating device 28 inaccordance with various embodiments. In some embodiments, the downholetag 26 is mounted on an exterior surface of a drill string component toprovide the tag 26 with access to the wellbore environment. As shown inFIG. 3, the tag 26 is mounted to an exterior surface of the drill pipe18. The drill pipe 18 includes a pocket 32 disposed to receive the tag26. The tag 26 may be affixed to the drill pipe 18 by a snap ringdisposed in a groove of the pocket 32, epoxy or other adhesive bondingthe tag 26 to the drill pipe 18, or other retaining means.

As the tag reader 28 traverses the interior of the drill pipe 18, thetag reader comes within communication distance of the tag 26. The tag 26and the tag reader communicate wirelessly through the wall of the drillpipe 18. Wireless communication through the metal wall of the drill pipe18 is achieved by including long wavelength inductive transceivers inthe tag 26 and the tag reader 28. The magnetic waves produced by thetransceivers propagate through the metallic wall of the drill pipe 18.As the tag reader 28 comes into communication proximity of the tag 26,the tag 26 and the tag reader 28 detect wireless transmissions from oneanother, establish a bidirectional wireless communication session, andtransfer information stored in the tag 26 to the tag reader 28. The tagreader 28 transmits the transferred information to the surface facility44, for example via the cable 42.

FIG. 4 shows a block diagram of a downhole tag 26 in accordance withvarious embodiments. An embodiment of the tag 26 includes an antenna420, a transceiver 418, a processor 402, program/data storage 404, apower source (e.g., a battery 422), and at least some sensors 406. Asexplained above, the transceiver 418 operates in the long wavelengthband (<500 KHz) to wirelessly communicate with the tag reader 28. Insome embodiments, the transceiver 418 is configured to operate inaccordance with the RuBee, IEEE 1902.1 standard for wirelesscommunication. The antenna 420 converts signals provided to or from thetransceiver 418 between conducted and airwave forms.

The processor 402 is configured to execute instructions read from acomputer readable medium, and may, for example, be a general-purposeprocessor, digital signal processor, microcontroller, etc. Processorarchitectures generally include execution units (e.g., fixed point,floating point, integer, etc.), storage (e.g., registers, memory, etc.),instruction decoding, peripherals (e.g., interrupt controllers, timers,direct memory access controllers, etc.), input/output systems (e.g.,serial ports, parallel ports, etc.) and various other components andsub-systems.

The program/data storage 404 is a computer-readable medium coupled toand accessible to the processor 402. The storage 404 may includevolatile and/or non-volatile semiconductor memory (e.g., FLASH memory,static or dynamic random access memory, etc.), or other appropriatestorage media now known or later developed. Various programs executableby the processor 402, and data structures manipulatable by the processor402 may be stored in the storage 404.

Transducers of various types may be included in the sensors 406. Atemperature transducer 410, pressure transducer 412, and/or accelerationtransducer 408 may be provided. The temperature and pressure transducers410, 412 may be disposed to measure borehole temperature and pressure.The acceleration transducer 408 may be arranged to detect accelerationof the drill string component to which the tag 26 is affixed. In someembodiments, the acceleration transducer 408 comprises a multi-axisaccelerometer or a plurality of accelerometers arranged to detectdifferent directions of tag 26 acceleration.

Signals produced by the sensors 406 are digitized and provided to theprocessor 402. The processor 406 analyzes the signals in accordance withsensor processing programming 414 provided from the storage 404. Forexample, an embodiment of sensor processing 414 configures to theprocessor 402 to periodically store samples provided from each sensor406 in measurement storage 416.

Communication programming 424 configures the processor 402 to executethe protocols required to communicate with the tag reader 28.Communication programming 416 may also cause the processor 402 toprovide the stored transducer measurements 416 to the tag reader 28.

Some embodiments of the downhole tag 26 may include a power system thatomits the battery 422. Such embodiments may further omit the sensors 406and associated processing logic 414. Embodiments lacking the battery 422may be powered by energy drawn from the magnetic waves generated by thetag reader 28 and detected by the antenna 420. Information (e.g., tag 26identification information) may be stored in the program/data storage404 for transmission by the tag 26 when the tag communicates with thetag reader 28.

FIG. 5 shows a block diagram of a downhole tag interrogating device (tagreader) 28 in accordance with various embodiments. An embodiment of thetag reader 28 includes an antenna 516, a transceiver 510, a processor502, program/data storage 504, and a power system 514. As explainedabove the transceiver 510 operates in the long wavelength band (<500KHz) to wirelessly communicate with the downhole tag 26. The antenna 516converts signals provided to or from the transceiver 510 betweenconducted and airwave forms. Some embodiments of the tag reader 28 alsoinclude a wireline/wireless transceiver 512 (e.g., Ethernet, IEEE 802.3,IEEE 802.11, Bluetooth, etc.).

The processor 502 is configured to execute instructions read from acomputer readable medium, and may, for example, be a general-purposeprocessor, digital signal processor, microcontroller, etc. Processorarchitectures generally include execution units (e.g., fixed point,floating point, integer, etc.), storage (e.g., registers, memory, etc.),instruction decoding, peripherals (e.g., interrupt controllers, timers,direct memory access controllers, etc.), input/output systems (e.g.,serial ports, parallel ports, etc.) and various other components andsub-systems.

The program/data storage 504 is a computer-readable medium coupled toand accessible to the processor 502. The storage 504 may includevolatile and/or non-volatile semiconductor memory (e.g., FLASH memory,static or dynamic random access memory, etc.), or other appropriatestorage media now known or later developed. Various programs executableby the processor 502, and data structures manipulatable by the processor502 may be stored in the storage 504.

The communication software programming 506 stored in the storage 504configures the processor 502 to execute the protocols required to detectthe presence of the downhole tag 26, establish a communication sessionwith the detected tag 26, and wirelessly retrieve information, includingthe sensor measurements 416 from the tag 26. In some embodiments, theprocessor 502 may also be configured to set the downhole tag 26 to aninitial state after sensor measurements 416 have been retrieved, therebyconfiguring the tag 26 to acquire additional measurements.

Sensor measurements 416 and other information (e.g., identificationinformation) retrieved from the downhole tag may be stored in storage504 as measurements 508. In some embodiments, the communication softwareprogramming 506 configures the processor 502 to transmit themeasurements 508 and other information to the surface facility 44 viathe wireline transceiver 512 and the cable 42. In some embodiments, themeasurements 508 include measurements 416 retrieved from all downholetags 26 detected in the drill string 8. In some embodiments, thecommunication software programming 506 may configure the processor 502to transfer the measurements 508 to the surface facility 44 via thewireless transceiver 510 and/or the wireless transceiver 512 after thetag reader 28 has been extracted from the drill string 8. Variousembodiments of the reader 28 may be configured for operation in theinterior of the drill string as shown in FIG. 3. Other embodiments maybe configured for handheld operation and/or for disposal on the drillingplatform 2 to read retrieve tag information as the drill string 8 movesinto or out of the borehole 16. An embodiment configured for handheldoperation may include a display device (e.g., a liquid crystal display,organic light emitting diode display, etc.) and/or an input device(e.g., a keyboard, pointing device, etc.).

The power system 514 may include converters that convert the voltagesprovided to the tag reader 28 via power conductors of the cable 42 tothe voltages needed to power the components of the tag reader 28. Insome embodiments, the power system 514 comprises a battery andconverters that convert the voltages provided by the battery to thevoltages needed to power the components of the tag reader 28.

FIG. 6 shows downhole tag packaging in accordance with variousembodiments. As shown, some embodiments of the downhole tag packaginginclude an alignment feature (key or orientation key) 60. The alignmentfeature 60 guides the placement of the tag 60 on a downhole componentthereby controlling the orientation of acceleration transducers 408included in the tag 26 respective to the downhole component. Forexample, the alignment feature 60 may position the tag 26 on a drillstring component such that a first accelerometer is oriented to measureaxial (i.e., along the length of component) acceleration, and a secondaccelerometer is oriented to measure radial (i.e. lateral or rotational)acceleration. The axial acceleration measurement may be indicative ofaxial vibration and/or movement of the drill string 8 into or out of theborehole, and radial acceleration measurement may be indicative of drillstring 8 rotation. In some embodiments, measurements derived from theacceleration transducers 408 are used to log usage or operation of adownhole component. While the exemplary downhole packaging of FIG. 6 isshown as disk shaped, embodiments of the downhole tag packaging may useany of a variety of shapes.

FIG. 7 shows downhole tag packaging 700 in accordance with variousembodiments. The package 700 includes a base 708, an inner cover 704,and an outer cover 702. The package 700 may be formed fromPolyetheretherketone (“PEEK”) or other thermoplastics or materialssuitable for use in a downhole environment. The base 708 includes acavity 710 disposed to contain the antenna 706 (an embodiment of theantenna 420) and electronic components (e.g., transceiver 418, processor402, storage 404, etc). The inner cover 704 fits into the cavity 710 sothat the upper surface 712 of the inner cover 704 and the surface 716 ofbase 708 are coplanar (i.e., substantially coplanar). The ridges 714 ofthe inner cover 704 align with the ridges 718 of the base 708 to form acircular protrusion. In some embodiments, the inner cover 704 is bondedto the base 708 by friction welding along the bottom 722 and/or lateral720 surfaces of the inner cover 704. In some embodiments, other bondingmethods are employed (e.g., adhesives).

The outer cover 702 is bonded to the inner cover 704 and the base 708.The rim 726 of the outer cover 702 is configured to be inserted into andbonded to the bottom and/or sidewalls of the groove 724 of the base 708.The outer cover 702 is further configured to allow the upper interiorsurface of the cover 702 to contact and bond to the circular protrusionformed from the ridges 714, 718 of the inner cover 704 and the base 708.Friction welding (e.g., spin welding) may be used to bond the outercover 702 to the base 708 and the inner cover 704. Thus, the antenna 706and electronic components are sealed via the bonded base 708, innercover 704, and outer cover 702.

In some embodiments, the antenna 706 and electronic circuitry (e.g., aprinted circuit board including components 402, 418, 404, etc.) areinstalled in a cavity in the underside of the inner cover 704, and thecavity is filled with a potting compound (an encapsulating resin, e.g.,epoxy, urethane, silicone, etc) that when cured seals and protects thecircuitry. Thereafter, the inner cover 704 (including the sealedcomponents) is bonded to the cavity 710 of the base 708. The outer cover702 is then bonded to the base 702 and the inner cover 704.

In some embodiments, the assembled package 700 is encased in a sealedmetallic (e.g., stainless steel) enclosure to prevent migration of wateror other fluids into the package 700.

FIG. 8 shows a representation of sensor measurements indications 802,804 recorded by a downhole tag 26 in accordance with variousembodiments. Program/data storage 404 may be limited in some embodimentsof the downhole tag 26, thereby restricting storage available formeasurements 416. In some embodiments, the sensor processing logic 414may store a summary of sensor measurements to reduce measurement storagerequirements. The measurement summaries may take the form of histograms.The histograms provide a frequency distribution of the acceleration towhich the tag 26 is subject.

In FIG. 8, acceleration measurements 804 derived from axialaccelerometers 408 and acceleration measurements 802 derived from radialaccelerometers 408 are depicted. A number of acceleration ranges aredefined, and threshold values are set corresponding the defined ranges.For example, 12.5 g and 17.5 g threshold values may delimit the 15 gradial/axial acceleration range shown in FIG. 8. An axial accelerationvalue falling between the 12.5 g and 17.5 g threshold values may causean increase in a measurements 416 stored value indicative of the numberof 15 g axial accelerations detected. Threshold values may similarly beset for each defined acceleration range. Such summaries reduce storagerequirements while providing substantial information about the tagenvironment. Embodiments of the tag 26 may provide stored measurementsummaries corresponding to any of sensors 406.

Some embodiments of the downhole tag 26 use acceleration measurements toascertain and log use/operation time of a drill string 8 component. Forexample, the drill pipe 18 includes the downhole tag 26 comprisingmulti-axis acceleration sensors 408. The tag 26 may include atime-keeping device (i.e., a clock), acceleration measurement storage(e.g., acceleration summaries 802, 804), and stored indications of theduration of drill pipe 18 use (e.g., time of use indicators, such as usestart and end times). When the drill pipe 18 is transferred to a user,time of use indicators in the tag 26, acceleration summaries, etc. maybe reset using a device configured to wirelessly communicate with andinitialize the tag 26 (e.g., a device similar to the tag reader 28).Thereafter, the tag 26 may periodically compare accelerationmeasurements provided by the acceleration sensors 408 to use thresholds(e.g., an axial use threshold and a radial use threshold) to determinewhether the drill pipe 18 has been put into and/or is continuingservice.

When the drill pipe 18 is installed in the drill string 8, and anacceleration measurement exceeds a use threshold, the tag 26 may set astored use start time (e.g., set a use start time indicator to thecurrent clock time) indicating that the drill pipe 18 is in use.Thereafter, the tag 16 may periodically (e.g. every 60 seconds) compareacceleration measurements to the continuing use thresholds. If thecontinuing use thresholds are exceeded, the use end time indicator willbe updated to the current clock time. Thus, the duration of drill pipe18 use may be recorded in the tag 26.

As the drill pipe 18 is being used, the tag 26 may also log accelerationmeasurements. Logged acceleration measurements may take the form ofsummaries as described above with regard to FIG. 8, and/or accelerationas a function of time. The use time acceleration data may be extractedfrom the drill pipe 18 and employed to analyze cumulative damage to thedrill pipe 18, or to improve future designs.

FIG. 9A shows an adapter 904 for attaching a tag 912 to a wellboretubular 902 in accordance with various embodiments. The tag 912 may be,for example, a radio frequency identification (“RFID”) tag as known inthe art, the downhole tag 26, or another identifying/tracking device.The adapter 904 is configured to package the tag 912 and protected thetag 912 from damage. The underside 906 of the adapter 904 is configuredfor attachment to an exterior surface of the wellbore tubular 902. Thetubular 902 may be, for example, a well casing. The underside 906 of theadapter 904 may have substantially the same radius of curvature as thetubular 902 onto which the adapter 904 is to be installed.

The upper side 908 of the adapter 904 has a radius of curvature smallerthan that of the underside 906 causing the upper side 908 of the tag 904to extend outward from the underside 908. A depression or pocket 910 isdisposed in the upper side 908 of the adapter 904. The tag 912 ispositioned in the pocket 910 and affixed to the adapter 904. Thus, ifthe tubular 902 is rolled, or impacts another object, the adapter 904will absorb the impact load and protect the tag 912. FIG. 9B shows aclose-up view of the adapter 904.

FIG. 10 shows a flow diagram for a method for retrieving informationfrom a downhole tag 26 in accordance with various embodiments. Thoughdepicted sequentially as a matter of convenience, at least some of theactions shown can be performed in a different order and/or performed inparallel. Additionally, some embodiments may perform only some of theactions shown. In some embodiments, the operations of FIG. 10, as wellas other operations described herein, can be implemented as instructionsstored in a computer readable medium (e.g., storage 404, 504) andexecuted by one or more processors (e.g., processor 402, 502).

In block 1002, a drill string 8 is present in a borehole 16. At leastsome components of the drill string 8 include a downhole tag 26 affixedto an exterior surface of the component. As the drill string 8 operatesin the borehole 16, the tag 26 acquires information indicative ofdownhole conditions (e.g., borehole 16 environmental information anddrill sting 8 operational information) and stores the acquiredinformation in the tag 26.

In block 1004, in at least some embodiments, the drill string 8 remainsin the borehole 16, and the tag reader 28 is lowered into the interiorof the drill string 8. The tag 26 and the tag reader 28 include longwavelength inductive transceivers that allow the tag 26 and the tagreader 28 to communicate through the wall of the drill string componentto which the tag 26 is affixed. The tag reader 28 is connected to asurface facility 44 by a cable 42, which the surface facility 44 uses tocontrol the traversal of the tag reader 28 through the drill string 8.In some embodiments, the surface facility 44 provides power to the tagreader 28 via power conductors included in the cable 42.

In other embodiments, the tag reader 28 is handheld and manually movedinto communication range of a tag 26 outside of the borehole 16. In yetother embodiment, the tag reader 28 is disposed on the drilling platform2 and tags 26 move into communication range of the reader 28 as thedrill string 8 moves into or out of the borehole 16.

In block 1006, as the tag reader 28 moves through the interior of thedrill string 8, the tag reader 1006 detects the tag 26. Detection mayinclude identifying the presence of a tag 26 transmission as the tagreader 28 moves to within communication range of the tag 26.

In block 1008, the tag reader 28 establishes communication with the tag26. In some embodiments, establishing communication includes exchangingaddressing and/or protocol information used to direct and transferinformation between the tag 26 and the tag reader 28.

In block 1010, the tag reader 28 retrieves the information indicative ofdownhole conditions stored in the tag 26. The information may include,for example, a log of borehole temperature and/or pressure, and/orstresses experienced by the drill string component to which the tag 26is affixed. As mentioned above, the tag 26 and the tag reader 28 uselong wavelength inductive transmission to communicate through the wallof the drill string 8.

In block 1012, the tag reader 28, provides the retrieved information toa surface facility 44 for analysis. In some embodiments, the tag reader28 transmits the information to the surface facility 44 via dataconductors included in the cable 42. In some embodiments, theinformation is stored in the tag reader 28 and retrieved by the surfacefacility 44 after the tag reader 26 is extracted from the tool string 8.

In block 1014, the tag reader 28 has retrieved the information stored inthe tag 26 and sends a message to the tag that causes the tag toinitialize (e.g., to prepare itself to acquire and store additionalinformation). Initialization may include clearing memory used to storeinformation indicative of downhole information, and/or resettingpointers or indices indicating where newly acquired information is to bestored, and/or setting the tag 26 clock, etc.

FIG. 11 shows a flow diagram for a method for storing information in adownhole tag in accordance with various embodiments. Though depictedsequentially as a matter of convenience, at least some of the actionsshown can be performed in a different order and/or performed inparallel. Additionally, some embodiments may perform only some of theactions shown. In some embodiments, the operations of FIG. 11, as wellas other operations described herein, can be implemented as instructionsstored in a computer readable medium (e.g., storage 404) and executed byone or more processors (e.g., processor 402).

In block 1102, a downhole tag 26 is affixed to a component of a drillstring 8 and is acquiring data downhole via the sensors 406. Morespecifically, the tag 26 is acquiring acceleration data fromacceleration transducer(s) 408. Acceleration transducers 408 may beconfigured to measure acceleration along multiple axes of the drillstring component. For example, accelerometers 408 may measure axial andradial acceleration of the drill string component to which the tag 26 isaffixed. While the following operations are directed to acquiring andstoring acceleration information, those skilled in the art willunderstand that the tag 26 may include other transducers (e.g.,temperature 410, pressure 412, etc.) and at least some of the operationsdepicted are equally applicable to acquiring and storing informationfrom other transducers included in the tag 26.

In block 1104, the tag 26 determines the degree and direction ofacceleration detected by the accelerometers 408. Some embodiments of thetag 26 sort and store acceleration data according to the determineddegree and direction of detected acceleration.

In block 1106, the tag compares the acceleration data to predeterminedthresholds. The thresholds may correspond to degrees of accelerationdeemed to indicate that the drill string component has been put into useand/or to various predetermined ranges of acceleration selected for usein summarizing the acceleration measurements. Different thresholds maybe established for acceleration in different directions.

In block 1108, the tag 26 determines whether the drill string componentto which the tag 26 is affixed is already in use. Such determination maybe made by testing a flag or value stored in the tag 26 that is setbased on determining that an acceleration measurement compared to a usethreshold indicates that the component has transitioned from disuse touse.

If the drill string component is not yet in use, then, in block 1110,the tag 26 determines whether the detected acceleration exceeds thepredetermined use start threshold. If the detected acceleration exceedsthe start threshold, then the tag 26 sets the stored use start time inblock 1112. In some embodiments, setting the use start time includessetting a start time memory location of the tag 26 to a current timemaintained by a clock in the tag 26. Setting the start time indicatesthat the drill string component has been put into use.

If the drill string component is in use, then, in block 1114, the tag 26determines into which of a plurality of predetermined accelerationsranges or bins, the detected acceleration falls. The bin determinationmay be based on the threshold comparison of block 1106, whereinthreshold values define the bins (e.g., a pair of threshold valuesdefine each bin).

In block 1116, a value stored in the tag 26 indicating a number ofdetected accelerations corresponding to the acceleration range (i.e.,the bin) of the detected acceleration is updated (e.g., incremented). Insome embodiments, a stored use end time value is also updated. Forexample, the end time memory value may be set in accordance with a clockmaintained in the tag 26. The end time value may be updated based on thedetected acceleration exceeding a predetermined continuing use thresholdvalue. The continuing use threshold value may be less than or equal tothe threshold value used to determine whether the component hastransitioned from disuse to use.

In block 1118, the tag 26 transmits acquired acceleration and/or useand/or other sensor information to a tag reader 28. In some embodiments,the tag reader may traverse the interior of the drill string towirelessly collect information from the tag 26. In other embodiments,the reader 28 may be disposed on the drilling platform 2 to wirelesslyretrieve information from the tag 26 as the drill string 8 is removedfrom the borehole 8.

In block 1120, the tag 26 is initialized by the reader 28 after the tag26 has transferred sensor measurements, use information, etc. to thereader 28. Initialization prepares the tag 26 to collect additionalinformation.

FIG. 12 shows a system for acquiring information related to a downholeasset in accordance with various embodiments. The system includes adownhole asset (e.g., the drill pipe 18), a handheld tag reader 28, andone or more measuring instruments 1212. As explained above, the tagreader 28 is configured to wirelessly retrieve information stored in thetag 26, which may include information related to use of the drill pipe18, such as use time, rotation time, number of rotations, accelerations,and stresses encountered by the drill pipe 18.

A variety of other instruments 1212 may also be used to gatherinformation related to the physical condition of the drill pipe 18. Insome embodiments, such instruments include a wireless transceiver (e.g.,an IEEE 802.11, Bluetooth, etc. transceiver) for wirelessly transmittingmeasurements or other drill pipe physical condition information to thereader 28 or other platform 2 local collection device (e.g., a networkaccess point).

The instruments 1212 may include an inside diameter gauge 1202, threadtaper gauge 1204, thread depth gauge 1206, thread stretch gauge 1208,and/or a caliper 1210 for measuring inside and/or outside assetdiameter. As explained above, some embodiments of the instruments 1212wirelessly transmit measurements (e.g., when an operator determines thatthe measurement is complete) to the reader 28 and/or other destination,thereby improving the speed and accuracy of measurement acquisition.

Embodiments of the tag reader 28 include a wireless transceiver 512(e.g., an IEEE 802.11, Bluetooth, etc. transceiver) configured toreceive measurement information transmitted by the instruments 1212. Thetag reader 28 may use the transceiver 512 (or another transceiverincluded in the reader 28) to transmit asset physical conditioninformation received from the instruments 1212 and tag informationretrieved from the tag 26 to a local and/or remote data storage systemvia, for example, a network access point. In some embodiments, the tagreader 28 stores drill pipe 18 physical measurement information instorage 504 and transmits the information based on instruction of theoperator, or automatically (without operator instruction).

FIG. 13 shows a block diagram of a system 1300 for processinginformation related to a downhole asset in accordance with variousembodiments. The system includes a tag reader 28, a network 1306, a riginterface 1302, a remote datacenter 1304, and rig and remote databases1312, 1314. The tag reader 28 may be, for example, handheld, disposed onthe drilling platform 2, or in the interior of the drill string 8.Information related to a downhole asset (i.e., a drill stringcomponent), such as the drill pipe 18, is stored in the tag reader 28.The information may include drill string component use and/or boreholeinformation retrieved from a tag 26, and/or drill string componentphysical information provided from instruments 1212.

The tag reader 28 may transmit the information via the network 1306. Thenetwork 1306 may comprise any available computer networking arrangement,for example, any one or a combination of a local area network (“LAN”), awide area network (“WAN”), a metropolitan area network (“MAN”), theinternet, etc., or may comprise a proprietary network. Further, thenetwork 120 may comprise any of a variety of networking technologies,for example, wired, wireless, or optical techniques may be employed.Accordingly, the components of the system 1300 are not restricted to anyparticular location or proximity to the tag reader 28.

The rig interface 1302 may store, process, and/or display informationrelated to drill string component use and physical parameters providedby the tag reader 28, manual entry, and/or other sources. The riginterface 1302 may store in the rig database 1312 (e.g., a relational orobject oriented database) drill string component information received,for example, from the tag reader 28 or the remote datacenter 1304.

The rig interface 1302 may transfer stored asset information to the tagreader 28 and/or the remote data center 1304 via the network 1306. Forexample, the tag reader 28 (e.g., a handheld tag reader) may retrieveidentification information from tag 26 affixed to a drill stringcomponent, and provide the identification information to the riginterface 1302. Based on the provided identification information, therig interface 1302 my transfer stored asset information (e.g., physicalparameters, etc.) to the tag reader 28 for storage and/or display.

The remote datacenter 1304 is remote from the platform 2 may storeinformation related to downhole assets, such as drill string components,that are or have been used on numerous different drilling platforms. Theremote datacenter 1304 may store such information in the remote database1314 (e.g., a relational or object oriented database). Thus, the remotedatacenter 1304 may store data acquired over the life of a downholeasset for assets used on a plurality of rigs. For example, the remotedatacenter 1304 may store asset information for all assets provided froma given manufacturer and/or for which information is received from a riginterface 1302. As explained above, such information may be transferredto the remote datacenter from the rig interface 1302 or other sourceautomatically and without operator intervention. The remote datacenter1304 may provide a web interface allowing a user to access downholeasset information via a web browser.

The rig interface 1302 and/or the remote datacenter 1304 may process theasset information to determine how the working life of the asset hasbeen affected by the stresses to which the asset has been subjected.Because components of a drill string are subject to different levels andtypes of stress (e.g., due to weight and/or inclination), effects oneach drill string component are individually determined. Based on suchdetermination, the use of the asset (e.g., the position of the asset indrill string 8) may be planned to optimize asset working life.

The rig interface 1302 and the remote datacenter 1304 may be implementedusing one or more computers as are known in the art. For example,desktop computers, notebook computers, server computers, etc. may beused. Such computers generally include one or more processors, a displaydevice, and input device, storage device, input/output devices, etc. Thedatabases 1312, 1314 may be databases as known in the art (e.g.,relational, object oriented, etc.) local to or remote from the riginterface 1302 or the remote datacenter 1304.

FIG. 14 shows a flow diagram for a method for processing informationrelated to a downhole asset in accordance with various embodiments.Though depicted sequentially as a matter of convenience, at least someof the actions shown can be performed in a different order and/orperformed in parallel. Additionally, some embodiments may perform onlysome of the actions shown. In some embodiments, the operations of FIG.14 can be implemented as one or more computers executing instructionsstored in a computer readable medium.

In block 1402, a measuring instrument 1212 acquires and transmitsinformation related to physical parameters of downhole asset (e.g.,dimensional information) to a platform 2 local facility, such as the riginterface 1302. The downhole asset may be, for example, a drill pipe 18.In some embodiments, the information is initially transmitted to a tagreader 28, and thereafter transmitted from the tag reader 28 to thelocal facility. The local facility may store, process, and/or displaythe information.

In block 1404, a tag reader 28 retrieves use information (e.g.,acceleration summaries) and/or borehole information (e.g., temperature,pressure, etc.) from a tag 26 affixed to a downhole asset. The tagreader 28 may be handheld, platform 2 mounted, or within the drillstring 8. The tag reader 28 transmits the information to the localfacility. The local facility may store, process, and/or display theinformation.

In block 1406, the local facility may transmit the downhole asset useand physical information, and/or the borehole information to a remotedatacenter 1304. The remote datacenter 1304 may include a database forstorage of asset information.

In block 1408, the remote datacenter 1304 and/or the local facility mayanalyze information pertaining a given downhole asset and determine thecondition of the asset. The analysis may consider the use informationretrieved from the tag 26, such as determined use time, rotationalinformation, inclination information, acceleration information,stresses, pressure and temperature to which the asset has been exposed.The analysis may also consider measurement information, such as changesin asset diameter and/or thread condition. In some embodiments, theremote datacenter 1304 may analyze information pertaining to a pluralityof downhole assets of the as part of determining the condition of agiven instance of that type of asset. For example, use and conditioninformation acquired with regard to a particular model of drill pipe maybe analyzed to determine the condition of a particular joint of thatmodel of drill pipe. Thus, cumulative information regarding a joint ofdrill pipe may be based on all acquired information related to use andcondition of that type of drill pipe. Alternatively, cumulativeinformation regarding a joint of drill pipe may be based on informationrelated to use and condition of that joint of drill pipe or a selectedset of drill pipe (e.g., drill pipe used in similar conditions).

In block 1410, the remote datacenter 1304 may transmit cumulativeinformation regarding a downhole asset to the rig interface 1302. Therig interface 1302 may transmit cumulative information regarding adownhole asset to a handheld tag reader 28.

In block 1412, cumulative downhole asset information, or a subset of thecumulative information (e.g., information related to a use of a givenasset during a prescribed time period) is displayed. Display may beprovided, for example, via a web interface executed by a web browser ora handheld tag reader 28 display.

In block 1414, asset use is planned and/or managed based on thecumulative asset information. By acquiring information specific to eachdownhole asset, rather than only information general to the drill string8, stresses unique to each asset can be identified, and using knowledgeof the different stresses encountered by each asset the working life ofeach asset can be maximized.

FIG. 15 shows a display 1500 of information related to a downhole assetincorporated in a drill string 8 in accordance with various embodiments.In some embodiments, the rig interface 1302 is configured to provide thedisplay 1500. The display 1500 includes a representation 1508 of theborehole 16 and/or the drill string 8. A portion 1502 of the drillstring 8 may be selected for further magnified display 1504. A givencomponent 1506 of the displayed drill string 8 portion 1504 may be yetfurther selected. Information specific to the selected component 1506are further displayed 1510.

Buttons 1512-1518 allow an operator to control the type of informationprovided in display 1510. For example, button 1512 may provide fordisplay of asset dimensional information (measured or specification),button 1514 may provide for display of operation time information forthe selected asset 1506, button 1516 may provide for display of chartsrelated to asset 1506 operational parameters (e.g., acceleration,temperature, etc.), and button 1518 may provide for display of asset1506 ownership information.

FIG. 16 shows a display 1600 of use information for a downhole asset inaccordance with various embodiments. The downhole asset may be a givencomponent of the drill string 8, such as a drill pipe 18. In someembodiments, each row 1618 of the display 1600 is indicative of a singletrip. The time period relevant to the display 1600 is shown in field1602. Distributions of speed and torque experienced by the asset areshown in histogram form in fields 1604 and 1606 respectively.

Cumulative fatigue, displayed in field 1508, may be computed based ontrajectory of the asset in the borehole 16, torque and speed applied tothe asset, the weight on the drill bit 14, and rate of penetration. Atleast some of the information used to provide the displays 1604-1608 maybe provided from use information retrieved from the tag 26 affixed tothe asset.

Cumulative rotations of the asset are displayed in field 1608. Hoursdrilling rotating for the asset are displayed in field 1612. Hoursdrilling sliding are displayed in field 1614. Hours tripping for theasset are displayed in field 1616.

FIG. 17A shows further embodiment of a system 1700 for providing usagetime information for a downhole tool. The system 1700 includes adownhole tool 1702 and thread protector cap 1704 threadingly coupled tothe tool 1702. The downhole tool 1702 may be a drill pipe 18, the drillbit 14, a bottom hole assembly component (e.g., a collar, tool sub,etc.), a component of the drill string 8, or any component incorporatinga threadform specified by the American Petroleum Institute. The threadsof the aforementioned tools and components are protected from damage bythread protectors, such as the cap 1704, when not in use.

The thread protector cap 1704 includes threads for coupling to the tool1702, and further includes an antenna 1710, a battery 1708, and tag1706. The tag 1706 may be the tag 26 described above (see FIG. 4) orequivalent, where the battery 1708 serves as the battery 422 to providepower to the tag 1706, and the sensors 406 include the antenna 1710. Thetag 1706 is configured to determine whether the cap 1704 is coupled tothe tool 1702. When the tag 26 detects that the cap 1704 is coupled tothe tool 1702, the tag 1706 deems the tool not in use. When the tag 26detects that the cap 1704 is not coupled to the tool 1702, the tag 1706deems the tool in use and records time values indicative of the time ofusage in storage 404. For example, when the tag 1706 detects that thecap 1704 has been removed from the tool 1702, the tag may record a usestart time. Thereafter, when the tag 1706 detects that the cap 1704 hasbeen re-installed on the tool 1702, the tag 1706 may record a use endtime or use duration value. The tag 1706 may record multiple useinterval values as the cap 1704 is removed and reinstalled on the tool1702 any number of times during a deployment interval. The tag 1706 isconfigured to wirelessly communicate the recorded use time values to atag reader 28 as disclosed herein. The usage time values may betransferred from the tag reader 28 to a system (e.g., a database) thatmonitors tool use.

The antenna 1710 may be a loop antenna that together with othercomponents of the tag 1706 (oscillators, filters, amplifiers, frequencydetectors, etc.) forms a proximity detector. The proximity detector isconfigured to detect metal (e.g., the threadform of the tool 1702)disposed near the antenna 1710. The tag 1706 is configured to identifythe proximity of the tool 1702 via a detection signature included in thetag 1706. For example, the proximity detector of the tag 1706 mayproduce a frequency within a predetermined range when the cap 1704 isthreaded onto the tool 1702, and the tag 1706 may be configured todetect oscillation within that range, thereby detecting whether the cap1704 is threaded onto the tool 1702.

FIG. 17A-C show an embodiment of the cap 1704 configured to couple tothe threads of a pin end of the tool 1702. Other embodiments of the cap1704 are configured to couple to the threads of the box end of the tool1702.

In an exemplary method of tracking tool use, the cap 1704 is threadinglycoupled to the tool 1702 at a facility from which the tool 1702 isdistributed (e.g., a tool rental facility). Before the tool leaves thefacility to be used, any usage time values stored in the tag 1706 arecleared. The tag reader 28 may be used to clear the usage time values bycommands wirelessly transmitted from the tag reader 28 to the tag 1706.As the tool is used in the field, the tag 1706 records tool usage timebased on detection of cap 1704 removal and reattachment to the tool 1702as explained above. When the cap 1704, along with the tool 1702, isreturned to the facility, the tag reader 28 wirelessly extracts thestored usage time values from the tag 1706. The extracted values may bestored in tool usage tracking system that, for example, monitors toollife in terms of time used.

The above discussion is meant to be illustrative of various embodimentsof the present invention. Numerous variations and modifications willbecome apparent to those skilled in the art once the above disclosure isfully appreciated. It is intended that the following claims beinterpreted to embrace all such variations and modifications.

1. A system for managing use of a downhole asset, the system comprising:a rig interface disposed proximate to a borehole being drilled, andconfigured to process information related to use and physical conditionof the downhole asset while drilling the borehole; a tag readerconfigured to transfer a measurement of an attribute of the downholeasset to the rig interface; a remote datacenter disposed remote from theborehole and configured to assess the condition of the downhole assetbased on information received from the rig interface and additionalinformation related to use of the downhole asset received by the remotedatacenter over the life of the downhole asset.
 2. The system of claim1, further comprising a remote database coupled to the remotedatacenter, and configured to store information related to use andphysical condition of the downhole asset over the life of the downholeasset.
 3. The system of claim 1, wherein the rig interface is configuredto transfer the measurement and the information related to the use andthe physical condition of the downhole asset to the remote datacenter.4. The system of claim 1, wherein the remote datacenter is configured tostore asset information for all downhole assets provided by a givenmanufacturer and for all assets for which information is received fromthe rig interface.
 5. The system of claim 1, wherein the remotedatacenter is configured to store asset information for a plurality ofdownhole assets provided by a plurality rig interfaces associated withdifferent rigs over the life of each asset.
 6. The system of claim 1,wherein the remote datacenter is configured to transfer as assessment ofthe condition of the downhole asset to the rig interface, the assessmentbased on information of asset use and condition received of the life ofthe asset.
 7. The system of claim 1, wherein the remote datacenter isconfigured to provide a display showing cumulative usage of the downholeasset, the display comprising an indication of cumulative fatigue damageto the asset.
 8. The system of claim 1, wherein the measurementcomprises at least one of tool use measurements acquired during tooloperation by a downhole tag attached to the tool and a measurement oftool physical parameters measure by and wirelessly transferred to thetag reader by a measurement device.
 9. A method for managing use of adownhole asset, the method comprising: transmitting, by a rig computer,first information regarding use and physical parameters of a downholeasset to an asset management computer remote from a drilling operationassociated with the rig computer; analyzing, by the asset managementcomputer, the first information in conjunction with second informationregarding use and physical parameters of a downhole asset acquired bythe asset management computer over the life of the downhole asset;planning use of the downhole asset in the drilling operation to extendthe life of the downhole asset based on the analyzing.
 10. The method ofclaim 9, wherein the analyzing comprising determining cumulative fatiguedamage to the downhole asset.
 11. The method of claim 9, furthercomprising: acquiring use information, by a downhole tag attached to thedownhole asset, during operation of the downhole asset; extracting theuse information wirelessly from the tag; and providing the useinformation to the rig computer.
 12. The method of claim 11, wherein theuse information comprises at least one of temperature, pressure, torque,and number of rotations.
 13. The method of claim 9, further comprising:measuring a physical parameter of the downhole asset; transmitting avalue produced by the measuring to a tag reader via wireless network;associating, by the tag reader, the value with downhole assetidentification wirelessly retrieved from a tag attached to the downholeasset; and transmitting, by the tag reader, the value and theidentification to the rig computer.
 14. The method of claim 9, furthercomprising: transmitting, by the asset management computer, thirdinformation indicative of the cumulative effects of use over the life ofthe downhole asset to the rig computer; and displaying, by the rigcomputer, the third information on display device.
 15. A system foracquiring data related to a downhole asset, the system comprising: aninstrument configured to measure a physical attribute of the downholeasset, the instrument comprising a wireless transceiver; anidentification tag affixed to the downhole asset, the tag configured towirelessly communicate information regarding the downhole asset; and atag reader comprising: a first wireless transceiver configuredwirelessly communicate with the instrument; and a second wirelesstransceiver configured to wirelessly communicate with the identificationtag; wherein the instrument is configured to wirelessly transfer ameasurement value corresponding to a physical measurement of thedownhole asset made by the instrument to the tag reader; and wherein thetag reader is configured wirelessly retrieve an identification valuefrom the tag and to associate the measurement value with theidentification value.
 16. The system of claim 15, wherein the instrumentis one of an inside diameter gauge, thread taper gauge, thread depthgauge, thread stretch gauge, and a caliper.
 17. The system of claim 15,wherein the instrument and the tag reader are configured to communicatevia one of a wireless personal area network and a wireless local areanetwork.
 18. The system of claim 15, wherein the second wirelesstransceiver of the tag reader and the identification tag are configuredto communicate via long wavelength wireless communication.
 19. Thesystem of claim 15, wherein the tag reader is configured to wirelesslytransfer the identification value and the measurement value to a systemthat estimate the life of the downhole asset based on the measurementvalue.